Wellbores are drilled into the Earth's formation to recover deposits of hydrocarbons and other desirable materials trapped in the formations. Typically, a well is drilled by connecting a drill bit to the lower end of a series of coupled sections of tubular pipe known as a drillstring. Drilling fluids, or mud, are pumped down through a central bore of the drillstring and exit through ports located at the drill bit. The drilling fluids act to lubricate and cool the drill bit, to carry cuttings back to the surface, and to establish sufficient hydrostatic “head” to prevent formation fluids from “blowing out” the wellbore once they are reached.
To sample and test fluids, such as deposits of hydrocarbons and other desirable materials trapped in the formations, a formation probe or tester is typically deployed in the well drilled through the formations. Various formation fluid testers for wireline and/or logging-while-drill applications are known in the art, such as those described in U.S. Pat. Nos. 4,860,581, 4,936,139, and 7,458,419. The entireties of these patents are hereby incorporated herein by reference.
Such formation fluid testers may include and utilize a focused probe apparatus, such as shown in FIG. 1. In FIG. 1, an apparatus 101 is shown that includes a first sealing element 111 and a second sealing element 121. The sealing elements 111 and 121 are two circular concentric sealing elements, in which the sealing element 111 is referred to as the “inner packer” and the sealing element 121 is referred to as the “outer packer.” The area within the sealing element 111 is defined as a sample flow path 113, and the area between the sealing element 111 and sealing element 121 is defined as a guard flow path 123. The outer diameter of the sealing element 121 may be about 4.75 inches (12.1 cm).
During a sampling operation, the apparatus 101 may be pressed against the wall of a subterranean formation of interest. Fluid may then be drawn from the formation through the apparatus 101 via the sample flow path 113 and the guard flow path 123. Because of the flow dynamics encountered within the formation, fluid drawn into and flowing through the sample flow path 113 tends to have less contamination, such as less drilling fluid filtrate, as compared to fluid drawn into and flowing through the guard flow path 123. The apparatus 101 shown in FIG. 1 may be suitable when sampling in formations having medium to high mobility, but may be less effective in formations having low mobility.